Over the last 25 years streamline modeling has proven to be a valuable technique within the field of reservoir engineering, primarily with respect to heterogeneous reservoirs undergoing convection dominated flows. To date, most applications have been performed on a full field level. In this research, streamline modeling is applied to individual wells on a near wellbore scale. The stability of the technique is achieved via first principle modeling using a time of flight algorithm in cylindrical
geometry utilizing logarithmic grid refinement. The modeling technique allows for an understanding of how near wellbore heterogeneities affect flow distribution and production. The model is expanded to evaluate various completion strategies, including a cased and perforated well with associated perforation and formation damage, as well as an open-hole completion with partial filter cake build-up.
To analyze the models, response surface methodologies are utilized. With respect to a cased and perforated well, the most statistically influential factors on both flow rate and skin are perforation permeability, number of perforations, damage zone permeability, damage zone radius, and perforation length, respectively. Various interactions are also significant, including perforation permeability with perforation length and damage zone permeability with damage zone radius. In relation to partial filter cake removal in an open-hole completion, only the area/angle of coverage has a significant effect on the productivity of a well.
The model contains numerous simplifying assumptions, including single phase incompressible flow in two dimensions for heterogeneous medium. Nevertheless, it has proven to provide stable and reliable results. Although implemented in two dimensions, the technique remains very useful in evaluating completion strategies and overall effectiveness, thereby offering significant potential to increase industry profitability. It is emphasized that an extension to three dimensional problems is
straightforward since the third dimension is linear along the well trajectory.
Further research incorporating the works of streamline modeling in Cartesian geometries will lead to a reduction in the simplifying assumptions, allowing for compressible multiphase flow and the inclusion of gravitational effects.
The Captain Field which lies off the coast of Scotland is a shallow sandstone reservoir (3000 ft) comprising clean, unconsolidated sand with high permeability (up to 5D). The oil is heavy and bottomhole temperature very low (30oC). Throughout the development of this field (14 years) two of the main challenges have been control of unconsolidated sand and maximising production of the oil by water injection to maintain reservoir pressure.
Particular attention has been paid to drilling and completion of the water injection wells. The drill-in fluid used was initially oil based mud but changing to water based drill-in fluid facilitated use of faster completion procedures. Initially, when using a water based drill-in fluid, displacement of the openhole to clear brine was always troublesome. This issue was resolved by the introduction of a new low temperature starch into the drilling operation. Adoption of the new formulation has facilitated a simpler, faster displacement operation and made it easier to test various techniques that are offered for filtercake clean up. Treatments, involving acetic acid released in situ, enzymes, sequestering agents, etc., provided questionable results. However, a breaker system that provides a delayed release of formic acid has recently been introduced and has led to a significant improvement in performance.
New techniques have introduced significant benefits, for example:
• the improved starch shortened the completion process by at least several hours of rig time,
• the four most recently completed wells which were all treated with the formic acid system had an average initial Specific Injectivity Index that was about 50% better than the average achieved for the first five wells that were completed with oil based mud.
The paper will present important aspects of the learning process on the Captain Field with particular emphasis on application of the new starch, and drilling/clean-up of the water injection wells.
Franco, Carlos Alberto (Ecopetrol S.A.) | Zabala Romero, Richard Disney (Ecopetrol S.A.) | Zapata Arango, Jose Francisco (Ecopetrol S.A.) | Mora, Edgar (Ecopetrol S.A.) | Botero, Oscar Fabian (Ecopetrol S.A.) | Candela, Carlos Hernando (Ecopetrol S.A.) | Castillo Mejia, Andres Felipe (Ecopetrol S.A.)
Condensate banking has been identified as one of the most potential damaging mechanism affecting the well productivity in Cupiagua Field. This gas-condensate giant field has reached an average recovery factor of 42% with recovery values of ~60% in some layers of field. The mitigation of condensate banking phenomena, among the other important damaging mechanism currently interacting along the entire productivity zones, has been one of the most relevant stimulation practice in the development strategy.
The mitigation of condensate banking led to optimize common stimulation practices to recover the productivity of gas-condensate wells, massive hydraulic fracturing and matrix stimulation with inhibited diesel and alcohol have been the most common practices implemented and optimized to mitigate condensate banking in Cupiagua field.
Since the field is being operated by ECOPETROL (Jun-2010), the mitigation of condensate banking was recognized as one of the most important stimulation challenges to be worked by stimulation team. The effective mitigation of condensate banking is a key to reach and even exceed the production targets set by ECOPETROL short and long term.
This paper describes all the engineering work carried out to implement a new stimulation technique based on the injection of inhibited dry gas. The performed lab job, the simulation runs, the engineering design and the field results are clearly described in the paper, the preliminary results are showing that now we have available a successful stimulation technique to remove and mitigate condensate banking. At the moment this stimulation strategy has been focused in to remove liquid saturation (condensate and water) and organic solids (especially asphaltenes) by incorporating alcohol and surfactants inside the gas stream. Future engineering job will be addressed to find a chemical blend that can improve the gas-treatment life, probably reducing critical liquid saturation or/and reducing the size of no mobile condensate rings.
Among the other important sources of damage, condensate banking has become the most important factor reducing the well potential of the majority of Cupiagua gas-condensate producer wells. The accumulated amount of condensate near the wellbore dramatically reduces the effective permeability to gas then decreasing the well productivity. When reservoir water is also being produced the problem become worst, this combination introduces a third phase to the reservoir inducing an additional reduction of the effective permeability to gas phase.
At current time, condensate banking is expected to be found anywhere in the reservoir because the current reservoir pressure is below the dew point pressure, water is also being produced from the majority of Cupiagua gas-condensate producer wells.
The use of inhibited diesel was the first stimulation attempt carried out to mitigate the problem of condensate banking. A non-ionic surfactant and a mutual solvent were added to the diesel to generate the stimulation blend, this blend was pumped under matrix conditions into the reservoir to reach 5 to 10 feet as penetration radius. Good results in terms of production increasing were observed at early production stages when reservoir pressure was slightly lower than dew point pressure. Very poor results were observed when reservoir pressure dropped below dew point pressure anywhere in the reservoir.
The stimulation using inhibited natural gas was implemented as the best alternative to reach longest radius of penetration. The gas was inhibited with mutual solvent, especial alcohol blend and organic scale dissolvers, this stimulation blend cover the main characteristics to mitigate condensate banking, liquid revaporization, reduction of interfacial tension, promotes water wettability, remove organic scales and break oil-water emulsions.
Germanovich, Leonid N. (Georgia Inst. of Technology) | Hurt, Robert S. (Georgia Inst. of Technology) | Ayoub, Joseph Adib (Schlumberger) | Siebrits, Eduard (Schlumberger) | Norman, David (Chevron Corp.) | Ispas, Ion (BP plc) | Montgomery, Carl T. (ConocoPhillips Company)
In this work, we argue that resistance (apparent toughness) to fracture propagation is an inherent characteristic of cohesionless particulate materials. We developed experimental techniques to quantify the initiation and propagation of fluid-driven fractures in saturated particulate materials. The fracturing liquid is injected into particulate materials, where the fluid flow is localized in thin, self-propagating, crack-like conduits. By analogy, we call these conduits ‘cracks' or ‘hydraulic fractures.' The experiments were performed on three particulate materials - (1) fine sand, (2) silica flour, and (3) their mixtures. Based on the laboratory observations and scale (i.e., dimensional) analysis, this work offers physical concepts to explain the observed phenomena. The goal of this study is to determine the controlling parameters of fracture behavior and to quantify their effects.
When a fracture propagates in a solid, new surfaces are created by breaking material bonds. Consequently, the material is in tension at the fracture tip. In contrast, all parts of the cohesionless particulate material (including the tip zone of the hydraulic fracture) are likely to be in compression. In solid materials, the fluid front lags behind the front of the propagating fracture. However, for fluid-driven fractures in cohesionless materials the lag zone is absent. The compressive stress state and the absence of the fluid lag are important characteristics of hydraulic fracturing in particulate materials with low, or negligible, cohesion. At present, two kinematic mechanisms of fracture initiation and propagation, consistent with both the compressive stress regime and the absence of the fluid lag, can be offered. The first mechanism is based on shear bands propagating ahead of the tip of an open fracture. The second is based on the reduction of the effective stresses and material fluidization within the leakoff zone at the fracture tip.
Our experimental results show that the primary factor affecting peak (initiation) pressure and fracture aperture is the magnitude of the confining stresses. The morphology of the fracture and fluid leakoff zone, however, changes significantly not only with stresses, but also with other parameters such as flow rate, fluid rheology, and permeability. Typical features of the observed fractures are multiple offshoots (i.e., small branches, often seen only on one side of the fracture) and the bluntness of the fracture tip. This suggests the importance of inelastic deformation in the process of fracture propagation in cohesionless materials. Similar to solid materials, fractures propagate perpendicular to the least compressive stress.
Scaling indicates that in the experiments performed in the regime of limited leakoff (i.e., the thickness of the leakoff zone is much smaller than the fracture length); there is a high-pressure gradient in the leakoff zone in the direction normal to the fracture. Fluid pressure does not decrease considerably along the fracture, however, due to the relatively wide fracture aperture. This suggests that hydraulic fractures in unconsolidated materials propagate within the toughness-dominated regime. This is the main conclusion of our work. In addition, the theoretical model of toughness-dominated hydraulic fracturing can be matched to the experimental pressure-time dependences with only one fitting parameter. Scale analysis shows that large apertures at the fracture tip correspond to relatively large 'effective' fracture (surface) energy, which can be orders of magnitude greater than typical for hard rocks.
In this work, we present a comprehensive experimental development focusing on four main parameters: (1) confining stresses, (2) fluid rheology, (3) injection rate, and (4) permeability. Another important conclusion is that the primary parameter in determining the peak injection pressure is that of confining stresses.
Coreflood experiments are an integral part of the selection and optimisation of scale inhibitor treatments, providing information on formation damage, inhibitor return profiles and dynamic retention isotherms. Comparative returns are often used to select the chemical for field treatments. However, significant discrepancies can arise between core and field in particular due to test methodology.
Here we describe advances over previous work when we demonstrated that test methodology can have significant consequences for the comparative inhibitor returns, particularly with respect to oversaturation. It was shown that many of the limitations can be overcome through appropriate simulation techniques (see SPE 131131).
Here, we present the results of laboratory core flood tests designed to examine the effect of core flood test methodology on the derived return isotherm. This work clearly identifies certain test artefacts, in particular inhibitor oversaturation, which can impact simulation from core to field, and presents supportive core flood data with respect to the modelled isotherms. Thus the paper directly addresses the procedures involved in core flooding, recommends approaches and test protocols which allow more appropriate product ranking and allow improved simulation from core to field.
Formation integrity is a critical confinement factor in any injection process such as waste injection, CO2 capture and storage, and thermal/pressure injection in oilfields. Rock can fail in tensile, shear or in combination of complex modes. In situ stresses variation caused by injection may shear the caprock posing continued risk of containment breach. We developed an integrated approach to predict the alteration of in situ stresses and shear failure potential by combining data from sonic logs, image logs, mini-frac test data, formation pressure measurement, and rock mechanical core test data. In this approach, three-dimensional Mechanical Earth Models containing the reservoir, overburden, under-burden and side-burden were constructed. Coupled simulations were then run between dynamic reservoir model and geomechanical model to quantify stresses change induced by injection. The resulted formation shear and surface heave will then be calculated regarding the location and timing of occurrence during the planed injection operations.
The methodology has been applied to several steam injection case studies in Northern Alberta oil sands area, Canada. Our analysis indicated that three years of steam injection would cause up to 2 MPa stresses contrast; formation shear failure was forecasted to occur earlier than formation tensile failure at a same time step; the calculated surface heave due to steam injection was around three 3 cm. The simulation results enabled the optimization of injection scheme and proactive monitoring plans to avoid catastrophic events.
It is widely understood that injection activities can induce additional stress fields that will couple with the original in situ stress field. An increased shear stress may cause serious formation shear issue, which will in turn compromise the integrity of caprock or/and casings. In Northern Alberta, Canada, caprock unintegrity is an important environmental concern in heavy oil thermal production. Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) are the two most popular thermal oil recovery methods in heavy oil reservoirs where the oil in the form of bitumen is essentially immobile [Butler, 1991, Clark, 2007].
Steam injection triggers complex thermal and hydraulic processes which can dramatically alter the formation pressure and temperature leading to various changes within the reservoir as well as in the surrounding rock. As steam is injected into reservoir, the pressure and temperature in the reservoir rise. The increased temperature and pressure cause changes in in situ stresses, rock properties, porosity, permeability, etc. High temperature and injection pressure can reduce rock strength, induce fractures. This poses a continued risk of breaching the containment of caprock, which can provide pathways for bitumen and steam to flow to aquifers or to the surface causing significant risk to safety and the environment. Therefore, ensuring caprock integrity is critical in any subsurface injection process such as SAGD and CSS.
Conventionally, fracture pressure typically measured/interpreted from mini-fracturing (mini-frac) test is considered as the upper limit of the net injection pressure. However, some cases of compromising the integrity of caprock have been reported despite keeping the net injection pressure below the fracture pressure. These cases clearly indicate that designing the injection pressure scheme solely based on mini-frac test is not sufficient. Because, fracture pressure estimated from mini-frac test considers tensile failure only. Rock can fail in tensile, shear or in combination of complex modes. Consideration of shear failure in addition to tensile failure must be an essential part of caprock integrity analysis.
Sourget, Adrien (Schlumberger) | Milne, Arthur (Schlumberger) | Diaz Torres, Lenin (Schlumberger) | Lian, Eric Gin Wai (Schlumberger) | Larios Leon, Humberto (Schlumberger) | Tejeda, Patricio (Pemex) | Macip, Miguel (Pemex E&P)
Water control is one of the greatest challenges in Southern Mexico wells, where the reservoirs are generally fractured carbonates. Many of the wells have early water breakthrough as a result of one or more of the following: water coning, near-wellbore flow, high-conductivity channels, high-conductivity layer breakthrough, segregated layering, and inadequate completions.
In cases where it is possible to shut off the producing interval and recomplete the well in a new interval, reticulated polymer gels and/or cement slurries can control water production. However, when the water is produced in a different interval than the oil, the success rate of reducing the water cut is less than 30%.
In these cases, waterless cement slurry squeezes have proven to be an effective solution to unwanted water production. This method has been used to successfully reduce water cut in several fields in South Mexico with a nearly 100% success rate.
A well which was carefully evaluated as a candidate and then treated with a waterless cement slurry resulted in a reduction in water cut from 71% to 5%, while oil production increased from 290 barrels of oil per day (BOPD) to 1054 BOPD. In addition, the deferred production was greatly reduced using this technique—less than four days compared with several weeks using alternative techniques.
Water cement squeezes are a cost-effective way to reduce water production in the producing intervals of naturally fractured reservoirs. This technique has increased oil production while resulting in significant cost savings in terms of both treatment costs and deferred production.
The leak-off of oil-based mud (OBM) into sandstone cores was studied both theoretically and experimentally. Simple models were used to describe the build-up of the external filter cake and the internal filtration of small particles. Then systematic static leak-off experiments were done using an innovative method where CT scans taken at time intervals were used to visualize and accurately quantify infiltration of fluids into sandstone cores. This method allowed the monitoring of the leak-off process in a way that could not be done by the traditional API filter paper press test. The composition of oil based drilling fluids was varied, to investigate the influence of various particles on the leak-off process. Scanning electron microscopy (SEM) was used to characterize the external filter cake and internal filtration. The core flow experiments were matched to the theory for linear static filtration. The results lead to new insights concerning the build of external filter cake and internal filtration. This work creates a basis for future improvement of oil-based mud, by providing a better understanding of mechanisms involved in leak-off process and its control.
The drilling of oil and gas wells requires careful formulation of the drilling fluids. Since the exploration and production of hydrocarbons has been moving to greater depths (e.g. Jellison et al. 2008), there is an increasing demand of oil-based drilling mud (OBM) that are stable at the high pressures and temperatures (HPHT) encountered at those depths. Besides being stable at HPHT conditions, OBMs have superior lubricating characteristics, great effectiveness against corrosion and ensure adequate cooling of the drill string and the drill bit (Aston et al. 2002; Bland et al. 2002; Bourgoyne et al. 1991).
A typical OBM consists of water-in-oil emulsions stabilized by a surfactant, to which other components are added to accomplish specific tasks (Bourgoyne et al. 1991). Lime Ca(OH)2 ensures the alkalinity of the water phase. A second surfactant dissolved in the oil phase modifies the wettability of drilled formations and of dispersed minerals from water-wet to oil-wet: this prevents adhesion of water droplets on mineral surfaces enhancing thus the stability of the OBM. Colloidal solids (e.g. Bentonite) dispersed in the oil increase the yield stress and the viscosity of the OBM, helping thereby the transport of the cuttings to the surface. Barite or calcium carbonate particles also dispersed in the oil increase the overall density of the drilling fluid, enabling good pressure control, wellbore stability and sealing the formation.
The Usan deepwater field, located approximately 100km south of Port Harcourt, has multiple oil bearing turbidite sand bodies of varying thickness and permeabilities separated by thin and massive shale intervals making difficult the selection of completion intervals. Fracture height confinement is challenging due to the small stress contrast between the sand bodies and the bounding shales, and variability of stress field in a very compartmentalized environment. Frac pack completions in this deepwater field were designed and executed to fulfill four main drivers:
• Ensure sand control completion integrity and long term reliability
• Deliver wells with low skin and good wellbore-fracture connectivity along entire completion interval
• Maximize reserves by increasing number of sand bodies connected by frac packs
• Reduce capital expenditure and installation risk by minimizing number of frac pack jobs
This paper illustrates the systematic approach used to optimize the frac pack completions in the Usan field by improving each of the following areas:
• Completion brine formulation to minimize emulsion and clay instability problems
• Perforation interval to maximize reservoir exposure without compromising frac pack quality
• Frac pack fluid testing to ensure low formation damage and stability at wellbore conditions
• Frac pack model calibration to improve fracture height coverage and confinement, and net pressure built after tip screen-out (TSO)
• Frac pack sensitivity analysis using two simulators accounting for uncertainty of input data and numerical modeling
• Post job analysis integrating surface and downhole data
• Well flow backs to evaluate initial completion integrity and performance
Actual field data from several wells are used to illustrate the evolution of the frac pack completions in the Usan project. The main challenges, lessons learned and improvement opportunities captured during the first two years of the Usan completions campaign are also discussed in detail.
Frac-packing has gradually become the standard completion technique for sand control in cased holes. As offshore development moves into more challenging deepwater environments, frac-packing technology continues to evolve and therefore brings new issues with the need for a better understanding to resolve them. One of the challenges is solids removal during the reverse out process in high-angle extended-reach large-diameter cased-hole wells.
In high-angle extended reach deepwater drilling, relatively large diameter connections are utilized to handle the tension load and torque. This geometrical environment, when using Bingham plastic or Power-law fluids and sufficient pump rate allows the flow to carry the solids and avoids formation of debris dunes in the areas adjacent to the tool joints. However, during the reverse circulation process, flow phenomena, such as fingering and dilution of the excess slurry with even small volumes of Newtonian brines coupled with low pump rates can create significant difficulties in the removal of solids from the inside of the workstring.
This problem manifests itself when some of sands from these dunes in the workstring are left in the wellbore after the frac-packing process is completed. During tripping of the pipe to extract the service tool, the solids in the workstring fall out of the tube as it goes from high angle sections to vertical. These solids remain in the wellbore and when the dune is of sufficient size or if pushed downhole, during the installation of the production tubulars, this debris can cause issues such as problems with the seal units testing, tagging sufficient debris to not allow seal latch-in, etc. Many times this situation is unavoidable and a special trip should be included to clean the wellbore.
The objective of this work is to study the effectiveness of circulating viscous sweeps to pick up the debris and clean the hole. This can be done by taking multiple aspects into consideration, including the annular and average fluid velocities at different regions of the eccentric annulus, rheological properties of the circulation fluid, density of the fluid and solids, size of the solids, size of the annulus, position of the drillpipe in the annulus or eccentricity, and wellbore angle. The mathematical approach for this research is based on previous works on drilling cuttings removal techniques. A model has then been developed to fit the described completion environment. The model is to estimate fluid velocity in eccentric annulus, based on fundamental concepts of transport phenomena, in combination with particle velocity in order to get an optimum range for the flow rate using the characteristics of Reynolds number and to find a balance between laminar and turbulent flow regimes to pick up the dunes. An experimental apparatus was also designed to simulate the solids removal process after the frac packing completion. Cuttings, suspended in different type of fluids, were circulated in an inclined annulus. The experimental data showed the mobility of solids all around the eccentric annulus and were used to fine-tune the mathematical model.
Utilizing the model and applying the fluid and solids characteristics for a particular completion, one can adjust and control the circulating pump rate in an optimal range. The model allows for the use of best and worst-case scenarios, to eliminate the dunes and also to save time by cleaning the wellbore with appropriate viscous sweeps during the completion and avoiding debris causing completion problems.